The present disclosure generally relates to forming a fluid seal in a wellbore, and, more specifically, to methods and treatment fluids that promote the formation of a fluid seal in a wellbore with enhanced uniformity.
Treatment fluids can be used in a variety of subterranean operations. Such subterranean operations can include, without limitation, drilling operations, stimulation operations, production operations, remediation operations, sand control treatments and the like. As used herein, the terms “treat,” “treatment,” “treating” and other variants thereof refer to any subterranean operation that uses a fluid in conjunction with achieving a desired function and/or for a desired purpose. Use of these terms does not imply any particular action by the treatment fluid or a component thereof unless expressly described as such herein. Illustrative treatment operations can include, for example, fracturing operations, gravel packing operations, acidizing treatments, scale dissolution and removal operations, consolidation operations, conformance control operations, and the like.
When performing a subterranean treatment operation, including those noted above, it can sometimes be desirable to temporarily or permanently block or divert the flow of a fluid within at least a portion of the subterranean formation by forming a fluid seal therein. The formation of a fluid seal can itself be considered a treatment operation. Whether the fluid seal is intended to be temporary or permanent can determine the type of agent used in its formation. Illustrative fluid blocking and diversion operations can include, without limitation, fluid loss control operations, kill operations, conformance control operations, and the like. The fluid that is being blocked or diverted can be a formation fluid that is natively present in the subterranean formation, such as petroleum, gas, or water. In other cases, the fluid that is being blocked or diverted can be a treatment fluid, including the types mentioned above. In some cases, treatment fluids can be formulated to be self-diverting, such that they are automatically directed to a desired location within the subterranean formation.
Providing effective fluid loss control during subterranean treatment operations can be highly desirable. The term “fluid loss,” as used herein, refers to the undesired migration or loss of fluids into a subterranean formation and/or a particulate pack. Fluid loss can be problematic in a number of subterranean operations including, for example, drilling operations, fracturing operations, acidizing operations, gravel-packing operations, workover operations, chemical treatment operations, wellbore clean-out operations, and the like. In fracturing operations, for example, fluid loss into the formation matrix can sometimes result in incomplete fracture propagation. Formation of a fluid seal in such treatment operations can mitigate the migration of a fluid into an unwanted location of the subterranean formation.
Likewise, in the reverse of a fluid loss event, incomplete fluid blocking can result in production of an unwanted fluid from one or more zones of a subterranean formation. For example, incomplete formation of a fluid seal may result in the unwanted incursion of formation water or brine into a wellbore, which may decrease the value of a hydrocarbon resource produced therefrom.
Gelled polymers, also synonymously referred to herein as viscosified gels, can be used to form a fluid seal in various subterranean operations.
As used herein, a “gelled polymer” or “viscosified gel” refers to a polymer in semi-solid form that has at least a portion of its polymer chains crosslinked with one another via a crosslinking agent. Gelled polymers can be further classified based upon their properties following gelation. “Lipping gels” or “tonguing gels” refer to crosslinked polymers that are more viscous than a freely pouring fluid phase, but have low gel strengths. They often form a retractable “tongue” over the edge of a container from which they are being poured. “Rigid gels” or “ringing gels,” in contrast, have higher gel strengths and generally refer to crosslinked polymers that are substantially non-flowing and maintain dimensional stability when in their crosslinked state. The properties of a particular gelled polymer can determine the types of treatment operations in which it may be most effectively used. Lipping gels are most typically used to provide viscosity to a treatment fluid during the treatment fluid's introduction to a subterranean formation. For example, lipping gels may be used to increase the viscosity of a fracturing fluid so that the fracturing fluid can effectively transport proppant particulates. Rigid gels, in contrast, are more typically used to form a temporary or permanent fluid seal in a subterranean formation. Generally, the two types of gels are complementary to one another in their use, and they are not usually thought to be operationally interchangeable with one another, although they may, at times, bear some similarity to one another from a viscosity standpoint. In this regard, lipping gels may be used for some conformance applications.
Various modes of crosslinking are possible in a gelled polymer. The crosslinks can be in the form of a covalent bond, a non-covalent bonding interaction, or any combination thereof. The crosslinks can be temporary or permanent. Chromium, titanium, zirconium and other transition metal ions can be used to crosslink certain types of crosslinkable polymers, including polysaccharides. Any suitable salt form of the transition metal ions, including ligated and solution forms, may be used to affect crosslinking. Borate or polyfunctional borate crosslinking agents can be used in a like manner. Polymer-based crosslinking agents may be used to affect crosslinking in other instances. A number of factors may determine the type of crosslinking agent chosen for a particular crosslinkable polymer, such as the desired gel time and gel strength, as well as the temperature and chemistry of a subterranean formation in which the crosslinkable polymer is deployed. For example, in higher temperature subterranean formations (e.g., above about 175° F.), polymer-based crosslinking agents may be more desirable than are transition metal ions due to uncontrolled crosslinking rates with the latter. As used herein, the term “gel time” refers to the time needed for an initially uncrosslinked polymer to form a substantially gelled state.
Due to their higher gel strengths, rigid gels are ordinarily used when forming a fluid seal in a subterranean formation. When forming a fluid seal with a rigid gel, the polymer and the crosslinking agent are usually introduced to the subterranean formation in a substantially non-crosslinked, low viscosity state. Otherwise, high viscosities would lead to difficult pumping, including high pump pressures and possible unintended fracturing, thereby making proper placement of the fluid seal problematic. Once the polymer and the crosslinking agent have reached their intended location in a subterranean formation, gelation can then take place to form a fluid seal. However, gelation does not take place instantaneously and is dictated by a number of factors including, for example, the nature of the polymer, the crosslinking agent, the formation temperature, and the downhole placement time, among other factors.
Because the polymer compositions that form rigid gels are fairly low in viscosity in their uncrosslinked state, they are often prone to slumping within a wellbore due to the influence of gravity before gelation occurs. Slumping can make it difficult to maintain an ungelled polymer in a desired location of the wellbore or to achieve an isotropic distribution of the ungelled polymer throughout the formation permeability while waiting for gelation to occur, often resulting in creation of an ineffective or incomplete fluid seal. Pressure differentials within a wellbore may also cause similar difficulties. Slumping effects may be particularly problematic in deviated wellbores having a substantially horizontal section, often resulting in ineffective generation of a fluid seal on an upper portion of the formation face. This issue can be especially problematic when well screens or slotted liners are present. Slumping and other types of polymer displacement issues may also be problematic in other wellbore configurations, including substantially vertical wellbore configurations. Although slumping may be combated to a certain degree by including an additive that hastens gelation, this approach may not be practical in all cases due to the risk of premature gelation occurring before the polymer has reached its intended downhole location. Even then, there may still be enough delay before gelation occurs to preclude formation of a sufficiently uniform fluid seal over the entire width of the wellbore. At present, there are not believed to be reliable options for placing a sealant composition in a wellbore without taking measures to account for slumping effects.